Oil storage tanks are used to hold oil for brief periods of time and can be a significant source of vapor gas emissions. Oil production units are located immediately upstream from an oil-well and often contain sedimentation storage tanks to separate oil from water. The oil output from the oil production unit is then stored downstream in a relatively large storage tank. These storage tanks are a significant source of vapor emissions. In particular, light hydrocarbons dissolved in the oil, including methane, vaporize and collect in the space between the oil and the storage tank's roof. These vapors can vent into the atmosphere over time. Traditional processes and devices to prevent emission of these light gas vapors involve processing oil before storage by, for example, burning the vapors or venting vapors to the atmosphere, as well as connecting vapor recovery units to the storage tanks. Burning the vapor gas is not, however, an ideal solution as such burning generates, for example, the greenhouse gas carbon dioxide. In addition, it is inherently dangerous to have flame in proximity to oil and the oil storage tanks.
It is important for oil-producers to address vapor gas emissions from oil stored within a storage tank because of the many state and federal regulations that govern emission levels. For example, the Colorado Dept of Public Health and Environment (CDPHE)/EPA is requiring a reduction in vapor gas emissions from oil consisting of a 37.5% reduction in 2005, 47.5% in 2006, and about 70% in 2007. Such restrictions on emissions levels means oil production tanks must be replaced or retrofitted to ensure continued compliance with the stricter guidelines. The present invention provides devices and methods for reducing vapor gas emissions that are both simple and cost-effective, but still comply with a variety of governmental guidelines, including those set by the CDPHE/EPA.
The volume of vapor gas generated by an oil-containing material located within a production unit's separator tank depends on many factors, including the composition of the oil. For example, lighter crude oils (API gravity >40°) vaporize more hydrocarbon vapors than heavier crudes (API gravity <40°). In addition, oil-fields often produce a mixture of oil-containing material and natural gas (e.g. gas obtained directly from the oil-field), as well as oil-containing material that comprises a mixture of oil and water. The pressure and temperature of the oil within the oil-well and the storage tank also affects the volume of gas vaporized from the oil. The composition of the natural gas also varies, although the largest component is methane (about 40% to 60%), with ethane, propone, isobutane, butane, isopentane, and most of the pentanes, hexanes and heptanes also commonly found. Similarly, the composition of gas vaporized from the oil-containing material also varies. Other gas vapors produced may include natural inert gases such as nitrogen and carbon dioxide, and hazardous air pollutants (e.g. benzene, toluene, ethyl-benzene and xylene). The natural and vapor gas contains natural gas and other liquids, so that this natural gas and vapor gas can have a relatively high Btu content (e.g. up to 2000 Btu per standard cubic foot (scf)) compared to that of pipeline quality natural gas (between about 950 and 1100 Btu per scf). As the price of natural gas continues to increase, the ability to successfully harvest natural gas generated from vaporization of oil within a storage tank gains economic importance, in addition to reducing air pollution.
Traditional vapor recovery units are comparatively complex and costly relative to the present invention and may not be suitable for the relatively smaller separation storage tanks commonly used in oil production units immediately downstream of the well-head. For example, those units generally require the use of a compressor and associated components to draw out hydrocarbon vapors from the storage tank under low-pressure. The drawn out vapors are subjected to a suction scrubber to condense and collect liquids. The vapors are then removed from the unit for pipeline sale or onsite fuel supply. The present invention is less complicated, and recovers vapors with a reduction efficiency up to 95% or greater, without the need for a compressor or a suction scrubber.
Disclosures relating to oil and gas separators, as well as oil producing devices (e.g. U.S. Pat. Nos. 1,752,215, 4,424,068, 6,293,340, 1,994,110, 1,649,556, 6,755,250, 4,482,364 and 4,559,068), suffer drawbacks, including being more complicated, inefficient for removing vapor gas from oil within a production tank, and/or requiring more maintenance that the present invention avoids. The present invention is different from many conventional devices in that it does not operate by centrifugally forcing liquid from the gas phase, but rather enhances condensation by increasing the residence time of gas flow within a practically-sized device and promoting reflux of condensed oil within the device.
The methods and devices presented herein alleviate the need for vapor gas combustors to burn off raw gas emissions to satisfy CDPDE/EPA regulations, as well as other state/federal regulations of vapor gas emissions, thereby avoiding the need to address anticipated regulations on combustor exhaust emissions. The invention also provides an increased volume of sales natural gas down the pipeline that is cleaner and dryer compared to those gases obtained from present separator oil-production units. In addition, collecting the vapor gas provides a fuel source that may be utilized by the on-site oil production unit to regulate and modulate operating temperature.
The methods and devices presented herein can operate at a higher temperature than the temperature generally used in a traditional oil production unit. Higher-temperature operating conditions offer several advantages. The sales gas temperature is between about 26° C. to 38° C. (80 to 100 degrees Fahrenheit), thereby reducing freeze problems. Paraffin buildup and related problems are reduced or eliminated. With traditional vapor recovery units, paraffin can clog the unit, requiring increased maintenance. This is avoided in the present invention, as the paraffin is liquefied and is heavier than liquid oil so that paraffin tends to remain in the production tank.
Maintenance is minimized in the present invention because there are no moving parts and few parts that are subjected to wear and/or clogging. The invention is also economical in that there is a short pay-out time period, typically less than 6 months at current natural gas prices, to recover the additional cost of the disclosed devices, including the LEE VGR™ vapor recovery unit.
Another advantage of the present invention is the relatively straight-forward operating parameters. The relatively straightforward operating properties of the present invention result in minimal special operator training; typically less than 30 minutes to educate that a higher operating temperature is important to maximize operation efficiency. In addition, the added components embodied by the present invention are easy to operate and maintain. For example, the column separator of the present invention requires no maintenance or cleaning, and the invention used with other components (e.g. a flash absorber exchanger) commonly found in oil-production units require minimal maintenance on the level controller and valve.
The method by which the low emission element functions is fairly simple and does not require expensive equipment. In fact, pre-existing oil-production units can be retrofitted, avoiding the need for complete replacement or overhaul of existing units to meet increasingly stringent vapor gas emission regulations, thereby minimizing costs and disruption to oil production.